This invention relates to an improved method for sand control in oil, gas and water wells and more particularly to a method for treating subterranean sand formations adjacent to a bore hole. The treatment is for the purpose of forming a permeable solid barrier which restrains the movement of sand particles while maintaining the permeability of the formations.
Production of oil, gas and water from unconsolidated or weakly consolidated formations is normally accompanied by the production of formation sand particles along with the produced fluids. The production of sand with the well fluids poses serious problems such as the erosion of sub-surface and surface production facilities and the accumulation of the sand in the wellbore and surface separators. Several methods such as gravel packing, screens and plastic consolidation have been in use for many years with varying success. However, these methods have several-technical and cost limitations.
Other method s for treating subterranean sand formations which are adjacent bore holes are disclosed in the Canadian Patent No. 700,740 of Marx, and in the U.S. Pat. No. 3,172,468 of Watson et al., U.S. Pat. No. 3,182,722 of Reed, U.S. Pat. No. 3,217,800 of Smith, U.S. Pat. No. 3,388,743 of Engle et al. and U.S. Pat. No. 3,974,877 of Redford. The methods disclosed therein consolidate incompetent formations by in-situ oxidation of heavy crude oil. Such methods are applicable to formations containing bitumen or heavy crude oil and utilize in-situ combustion involving high temperatures.
A Canadian patent No. 713,989 of Goodwin et al. discloses a method for consolidating heavy oil formations by oxidation of the heavy oil at a temperature of between 350 and 500xc2x0 F. Another Canadian patent No. 1,266,429 of Hanna discloses a method of treating an unconsolidated formation by heating heavy crude oil above ground level. The heated crude oil is then injected into the bore hole to heat the unconsolidated formation adjacent the bore hole to a temperature of between 35xc2x0-135xc2x0 C. (95xc2x0 F.-275xc2x0 F.). The elevated temperature supports the low temperature oxidation of the oil contained within the formation. Unheated oxygen containing gas is then injected into the bore hole and into contact with the heated formation to precipitate asphaltenes.
Another method for treating incompetent sand formations is disclosed in U.S. Pat. No. 3,910,351. As disclosed therein, a cavity is formed around a bore hole and 10-80 mesh sand introduced into the cavity. This step is then followed by the injection of bituminous petroleum. An asphalt-precipitating solvent is then injected followed by the injection of a heating fluid to solidify the precipitated asphalt.
In general, the previously mentioned processes use heavy crude oil that are either naturally present in the formation or heated and injected into the formation. In such cases, the oxidation temperature is higher than the formation temperature. Therefore, the processes are applicable to formations that are treated by the in-situ combustion process or in processes which involve extensive heating of the formation, crude oil and air with temperatures higher than the formation temperature. Furthermore, the use of heavy crude oil normally results in a significant loss of permeability and a reduced well productivity.
Accordingly, a prime object of the present invention is to develop a consolidating method using in-situ low-temperature oxidation (LTO) of a hydrocarbon material. This low temperature oxidation is obtained at a temperature close to the formation temperature and produces consolidated sand with a minimum loss of permeability and high compressive strength. This allows the maximum production of oil, gas or water without sand production. Further, the resulting consolidated sand is stable against the flow of formation fluids and other well-treatment fluids such as acids.
Several factors influence the low temperature oxidation process. For example there are the type of hydrocarbon material being oxidized, the oxidation temperature, the oxidation duration, the presence of catalytic materials (such as clay) in the sand and the sand grain size. The effect of these factors on the process can be expressed in terms of the degree of consolidation obtained as measured by the compressive strength of the consolidated sand, the retention of permeability and the stability against formation and treatment fluids.
In essence, the present invention contemplates an improved method for treating subterranean incompetent sand formations adjacent to a well or bore hole. This method or treatment is for the purpose of forming a permeable barrier which restrains the movement of sand particles and at the same time retains a high degree of permeability. The method includes the step of forming a consolidation fluid containing an asphaltene or preferably asphalt and a hydrocarbon solvent such as naphtha, reformate, or other aromatic solvent with a concentration of at least about 40 grams of asphaltene per 100 ml of solvent. In the preferred embodiments of the invention, the concentration of asphalt ranges from about 40 grams to about 80 grams of asphalt per 100 ml of solvent.
The consolidation fluid is then injected into the sand formation to saturate the sand in a zone around the bore hole. For example, the consolidation fluid is injected to saturate the sand for a radial distance of from about 1 to about 2 feet. This saturation step displaces any natural oils or water in the sand formation.
After injecting the consolidation fluid into the sand, an oxygen containing gas such as air is injected into the sand formation. This oxygen containing gas is injected at a temperature of about 100xc2x0 C. to about 150xc2x0 C. and preferably at a temperature of about 100xc2x0 C. The gas injection is continued for a period of time which is sufficient to solidify a thin film of asphaltene on the surface of the sand particles.
In a preferred embodiment of the invention, the method for treating subterranean incompetent sand formation includes the step of monitoring the oxygen content of an effluent gas until the oxygen concentration of the effluent gas is essentially the same as the oxygen concentration of the injected gas. When the oxygen content of the effluent gas is approximately equal to the oxygen content of the injected gas, the injection is stopped and the treatment has been completed.
The present invention relates to the in-situ consolidation of incompetent sand formations containing crude oil (heavy or light), gas or water. The incompetent sand is consolidated by means of low-temperature oxidation (LTO) of a hydrocarbon material that is either naturally present in or injected into the formation. This treatment creates a consolidated sand matrix around the well bore that has high compressive strength, minimum loss of permeability and stability against formation and well treatment fluids.
Several factors influence the low temperature oxidation process. For this reason, an experimental program was developed. That program will be described with reference to a number of examples. Such examples incorporated small sand packs, 2xe2x80x3 diameter by 4xe2x80x3 long and 1xe2x80x3 diameter by 2.5xe2x80x3 long. Different sand grain sizes representing different actual formations were tested. The oxidation was then conducted using different hydrocarbon material compositions, different oxidation temperatures, oxidation duration, different oxygen partial pressure and with and without the presence of catalytic materials in the sand packs. After determining the preferred oxidation (consolidation) conditions, consolidation tests were conducted on a full scale wellbore model resembling commercial wells to test the feasibility of field application of the process. These tests will be described hereinafter.
In one embodiment of the invention, an unconsolidated sand containing crude oil, gas or water was penetrated by a well bore. The unconsolidated sand was then treated by first injecting a slug of a specially prepared hydrocarbon fluid (hereinafter referred to as the consolidating fluid) to displace the naturally present fluid in the sand and saturate a zone around the wellbore extending 1 to 2 feet radially from the well bore. The consolidating fluid is preferably a solution of asphalt in a hydrocarbon solvent such as reformate or naphtha with a specific concentration. The preferred concentration is about 40 grams of asphalt per 100 ml of solvent. Other concentrations of 60 g/100 ml and 80 g/100 ml were also used to provide similar consolidation but with higher loss of permeability. Air at a temperature of 100xc2x00 Celsius was then injected into formation at a low flow rate of three to seven standard liters per minute per foot of sand thickness for a period of time ranging from about 24 to about 72 hours. The asphalt and solution is deposited on the surface of the sand grains and the solvent is displaced deeper into the formation. The low temperature oxidation solidifies the thin film of asphalt on the surface of the sand grains bonding the grains together while the permeability is maintained by the air flow. The loss of permeability is related to the thickness of the asphalt film deposited on the sand grain surface. Therefore, lower concentrations of asphalt in the solvent are preferred.
In another embodiment of the invention, the consolidating fluid comprises a heavy residue from a refinery such as atmospheric column bottom stock. Pure heavy residue is injected directly into the formation to saturate a zone around the wellbore extending for 1 to 2 feet into the formation. For low-permeability formations the refinery residue may be diluted in order to achieve injectivity. The residue is diluted by mixing with native formation oil. For example, the mixture may contain 75% residue and 25% oil or 50% residue and 50% oil.
In yet another embodiment of the invention, the consolidating fluid may comprise the native reservoir oil if it contains the appropriate concentration of asphaltene. Aged native oil is preferred over the freshly produced oil. The aging process results in increasing the concentration of the heavy ends and hence, improves the oxidation process.
In yet another embodiment of the invention, the consolidating fluid is a native reservoir oil which contains an appropriate concentration of asphaltene. Aged native oil is preferred over the freshly produced oil. The aging process results in increasing the concentration of the heavy ends and hence, improves the oxidation process.
The preferred oxidation temperature was found to be about 100 Celsius. However, the temperature may be raised up to about 150 Celsius to speed up the consolidation process without affecting the quality of consolidation.
In another embodiment of the invention, the formation around the wellbore is first cleaned by flushing the formation with a mutual solvent to remove both native oil and water away from the zone around the wellbore. A solvent such as COREXIT 8626 solvent AC (Isopropyl Cellosolve) or Butyl Cellosolve may be used for cleaning the sand formation from oil.
Another embodiment of the invention involves consolidation in wells that have been produced for a period of time during which significant amounts of sand have been produced. In such cases two procedures may be followed. In the first, the cavity around the wellbore may first be packed with sand having a specific grain size. For example, the preferred grain size is six times the size of the 50th percentile of the formation sand. The present consolidation process can then be employed to consolidate the sand that filled the cavity.
In a second procedure, the cavity around the wellbore may be maintained if the casing is not adversely affected, and the present consolidation process is performed on the sand beyond the cavity. This, in fact, may increase the well productivity as the cavity would have the effect of increasing the wellbore radius. In this case, however, the volume of the consolidating fluid injected should be enough to displace the fluid in the cavity and saturate the sand beyond the cavity.
It should also be recognized that in thick formations, the total interval should be divided into smaller zones (10-20 feet thick) and each zone should be consolidated separately with intermediate zone isolations.
The main objective of the present invention is to develop a consolidating method using in-situ LTO at a temperature close to the formation temperature and to produce consolidated sand with a minimum loss of permeability and high compressive strength. Such sand allows for the maximum production of oil, gas or water without sand production. Further, the resulting consolidated sand should be stable against the flow of formation fluids and other well-treatment fluids such as acids.
Factors which influence the LTO process include the type of hydrocarbon material being oxidized, the oxidation temperature, the oxidation duration, the presence of catalytic materials (such as clay) and the grain size of the sand. The effect of these factors on the process can be expressed in terms of the degree of consolidation obtained as measured by the compressive strength of the consolidated sand, the retention of permeability and the stability against formation and treatment fluids.